Hydrates For Well Control

ABSTRACT

Systems, apparatus, and methods for controlling a well blowout comprising: a flow control device such as a blowout preventer on a wellbore, the primary throughbore of the flow control device comprising internal dimensional irregularities creating a non-uniform flow path in the primary throughbore which as sufficient fluid rate may enhance pressure fluid pressure drop therein; a control fluid aperture fluidly connected with the wellbore for introducing a control fluid through a control fluid aperture and into the primary throughbore while wellbore fluid flows through the wellbore; a hydrate component introduction pump for introducing the hydrate inducing component into the control fluid; a hydrate inducing fluid aperture positioned in the wellbore conduit below the control fluid aperture for introducing the hydrate inducing fluid into the wellbore and for combining with the control fluid that includes the hydrate inducing fluid to form a saturated hydrate forming fluid mixture within the primary throughbore while control fluid is also being introduced into the wellbore through the control fluid aperture.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application62/786,870 filed Dec. 31, 2018 entitled “Hydrates for Well Control,” theentirety of which is incorporated by reference herein.

FIELD OF THE DISCLOSURE

The present disclosure is directed generally to apparatus, systems, andmethods for well control, such as may be useful in relation to ahydrocarbon well blowout event and more particularly to systems andmethods pertaining to an interim intervention operation for an out ofcontrol well.

BACKGROUND OF THE DISCLOSURE

Safety and time are of the essence in regaining control of a wellexperiencing loss of wellbore pressure control. Loss of pressure controland confinement of a well is commonly referred to as a “blowout.” Wellcontrol pressure management or “intervention” is required to regainpressure control and confine wellbore fluids within the formation andwellbore. Well control intervention is an important concern not only tothe oil and gas industry from a safety and operations standpoint, butalso with regard to protecting commercial, environmental, and societalinterests at large.

Well control intervention systems and methods are generally classifiedas either conventional or unconventional. Conventional interventionsystems are generally used when the well can be shut-in or otherwisecontained and controlled by the wellbore hydrostatic head and/or surfacepressure control equipment. In contrast, unconventional well controlintervention systems are generally used to attempt to regain control offlowing wells that cannot be controlled by the wellbore fluid and/orsurface pressure control equipment. Such “blowout” situation may resultfrom failure of downhole equipment, loss of wellbore hydrostaticcontrol, and/or failure of surface pressure-control equipment. In bothintervention classifications, the object of regaining well control is tohalt the flow of fluids (liquid and gas) from the wellbore, generallyreferred to as “killing” or “isolating” the well. Unconventional methodsare more complex and challenging than conventional methods andfrequently require use of multiple attempts and/or methods, oftenrequiring substantial time investment, including sometimes drillingrelief wells. Improved methods and systems for unconventional wellcontrol intervention are needed.

Unconventional well control intervention methods include “direct”intervention, referring to intervention actions occurring within thewellbore and indirect intervention refers to actions occurring at leastpartially outside of the flowing wellbore, such as via a relief well.Two known unconventional direct intervention methods include a momentumweighted fluid methods and dynamic weighted fluid methods. Momentumweighted fluid methods rely upon introducing a relatively high densityfluid at sufficient rate and velocity, directionally oriented inopposition to the adversely flowing well stream, so as to effect a fluidcollision having sufficient momentum that the kill fluid overcomes theadverse momentum of the out of control fluid stream within the wellbore.Such process is commonly referred to as “out running the well.” This isoften a very difficult process, especially when performed at or near thesurface of the wellbore (e.g., “top-weighted fluid”).

Dynamic weighted fluid methods are similar to momentum weighted fluidmethods except dynamic weighted fluid methods rely upon introduction ofthe weighted fluid stream into the wellbore at a depth such thathydrostatic and hydrodynamic pressure are combined within the wellboreat the point of introduction of the weighted fluids into the wellbore,thereby exceeding the flowing pressure of the blowout fluid in thewellbore and killing the well. Dynamic weighted fluid interventions arecommonly used in relief well and underground blowout operations, but arealso implemented directly in wellbores that contain or are provided witha conduit for introducing the weighted fluid into the wellborerelatively deep so as to utilize both hydrostatic and hydrodynamicforces against the flowing fluid.

However, each of the aforementioned well control procedures requiresignificant time to plan, deploy resources, and enact. Need remains foryet an additional well control intervention that can be relativelyquickly implemented as compared to the other intervention mechanisms. Anefficient response system is desired to provide interim well controlintervention that at least temporarily impedes or preferably halts theuncontrolled flow of fluids from an out of control wellbore and providesa time cushion until a more permanent solution can be developed andimplemented.

SUMMARY OF THE DISCLOSURE

Systems, equipment, and methods are disclosed herein that may be usefulfor intervention in a wellbore operation that has experienced a loss ofhydrostatic formation pressure control, such as a blowout. The disclosedinformation may enable regaining some control of the well, mitigatingthe flow rate of the blowout, and potentially even wholly halt theuncontrolled fluid flow. The disclosed technology includes creating ahydrate buildup within the wellbore that creates an impediment or plugthat prevents or restricts the blowout fluid flow rate.

The disclosed control system may be relatively quickly implemented as aninterim intervention mechanism to restrict or contain effluent from thewellbore so as to provide a time-cushion until a permanent well controlsolution can be implemented. Thereby, conventional and/or otherunconventional well control operations for a permanent or final solutionmay (subsequently or concurrently) proceed in due course to stop orcontrol the well effluent flowrate.

In one aspect, the methods disclosed herein may include systems,apparatus, and methods for controlling a well blowout comprising; a flowcontrol device such as a blowout preventer on a wellbore; a controlfluid aperture fluidly connected with the wellbore for introducing acontrol fluid through a control fluid aperture and into the wellborewhile wellbore fluid flows from the subterranean formation through thewellbore; a hydrate inducing fluid aperture positioned in the wellboreconduit below the control fluid aperture for introducing a hydrateinducing fluid into the wellbore while control fluid is also beingintroduced into the wellbore through the control fluid aperture.

In an aspect, the primary throughbore of the flow control devicecomprising internal dimensional irregularities creating increasedfriction through a hydro-dynamically tortuous or non-uniform flow pathin the primary throughbore, or such as drill pipe or other toolspositioned therein.

In another aspect, the processes disclosed herein may include a methodof performing a wellbore intervention operation to reduce anuncontrolled flow of wellbore fluids from a subterranean wellbore, themethod comprising: providing a flow control device, the flow controldevice engaged with a top end of a wellbore conduit that includes awellbore throughbore, the flow control device including a primarythroughbore that comprises at least a portion of the wellborethroughbore, the primary throughbore being coaxially aligned with thewellbore throughbore; providing a control fluid aperture in at least oneof (i) the top end of the wellbore conduit, (ii) the flow controldevice, and (iii) a location intermediate (i) and (ii), the controlfluid aperture being fluidly connected with the wellbore throughbore;providing a hydrate inducing fluid aperture into the wellborethroughbore at an upstream location in the wellbore throughbore withrespect to flow of wellbore blowout fluid flowing through the wellborethroughbore (that is, below the control fluid aperture); introducing acontrol fluid through the control fluid aperture and into the wellborethroughbore while a wellbore blowout fluid flows from the subterraneanformation through the wellbore throughbore at a wellbore blowout fluidflow rate, whereby the control fluid is introduced into the wellborethroughbore at a control fluid introduction rate that is at least 25%(by volume) of the previously estimated or determined wellbore blowoutfluid flow rate from the wellbore throughbore prior to introducing thecontrol fluid into the wellbore throughbore; and introducing a hydrateinducing fluid through the hydrate inducing fluid aperture and into thewellbore throughbore while pumping the control fluid through the controlfluid aperture.

In yet another aspect, the advantages disclosed herein may include anapparatus for performing a wellbore intervention operation to reduce anuncontrolled flow rate of wellbore blowout fluids from a subterraneanwellbore, the apparatus comprising: a flow control device, the flowcontrol device engaged with a top end of a wellbore conduit thatincludes a wellbore throughbore at a surface location of the wellboreconduit, the flow control device including a primary throughbore thatincludes the wellbore throughbore, the primary throughbore coaxiallyaligned with the wellbore throughbore; a control fluid aperture in atleast one of (i) the top end of the wellbore conduit, (ii) the flowcontrol device, and (iii) a location intermediate (i) and (ii), thecontrol fluid aperture being fluidly connected with the wellborethroughbore, the control fluid aperture for introducing a control fluidinto the wellbore throughbore while a wellbore blowout fluid flows fromthe subterranean formation through the wellbore throughbore at awellbore blowout fluid flow rate, whereby the control fluid isintroduced at a control fluid introduction rate of at least 25% (byvolume) of the wellbore blowout fluid flow rate from the wellborethroughbore prior to introducing the control fluid into the wellborethroughbore; a hydrate inducing fluid aperture in the wellborethroughbore positioned at an upstream location in the wellborethroughbore with respect to the control fluid aperture and with respectto direction of flow of wellbore fluid flowing through the wellborethroughbore, the hydrate inducing fluid aperture capable to introduce ahydrate inducing fluid into the wellbore throughbore while the controlfluid is introduced into the wellbore throughbore through the controlfluid aperture.

One collective objective of the presently disclosed technology iscreating a pressure drop in the flowing blowout fluid within the primarythroughbore by creating hydrodynamic conditions therein that approachthe maximum fluid conducting capacity of the primary throughbore, byintroducing control fluid therein. The prior art teaches momentumcontrols and dynamic controls that also utilize introducing fluid intothe wellbore conduit 10. However, the prior art types of interventionmechanisms typically rely upon introducing the fluid into the wellboreconduit as close to bottom hole source of the blowout energy as possiblein order to provide an increase hydrostatic column on the formation.That is, they require introducing a separate conduit such as coil tubingor drill pipe relatively deep into the wellbore to realize a hydrostaticbenefit and/or use momentum in the control fluid by vigorously directingthe control fluid directionally opposing the flow direction of theblowout fluid in effort to overwhelm the blowout fluid with momentumforces and eventual hydrostatic forces. Such technique is known in usingweighted drilling mud through a nozzle against a flowing gas stream. Incontrast to those prior art methods, according to the presently claimedtechnology a pressure drop is created within surface-accessibleequipment such as near or in the wellhead or related equipment, byoverwhelming the flow conduit therethrough with more fluid that theavailable pressure wellbore flowing pressure therein can move throughthe opening, thus creating an increase in pressure drop through thewellhead equipment. Successful implementation of the presently disclosedtechnology affords an additional method (in addition to the previouslyknown prior art methods) to achieve some measure of control over theblowout fluid in the most readily accessible points possible—within thewellhead or proximity thereto—while using readily portable equipment andwithout requiring introduction of a separate conduit or work string deepinto the wellbore or requiring removal of an obstruction or string fromtherein. Such successful implementation of the presently disclosetechnology may thus supplement the blowout intervention process,providing readily responsive action plan that provides a temporaryconstriction on the blowout until other methods such as momentum ordynamic kills or addition of a capping stack can be subsequentlyimplemented.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is an exemplary schematic representation of a well controloperation according to the present disclosure.

DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE

Relatively rapid access to processes and apparatus for controlling andkilling a well blowout may further benefit the energy industry. Thepresently disclosed technology is believed to provide functionalimprovements and/or improved range of methodology options overpreviously available technology. Methods and equipment are disclosedthat may provide effective interim control of blowout fluid flow from awellbore such that a more permanent well killing operation may beperformed subsequently or concurrently therewith. In many embodimentsthe presently disclosed well control operation methods may be applied inconjunction with performance of the long-term or “highly dependable”(permanent) kill operation. In some instances, the presently disclosedinterim technology may morph seamlessly from a “control” interventionoperation into a permanent well killing operation.

Certain key elements, components, and/or features of the disclosedtechnology are discussed herein with reference to FIG. 1, which ismerely a general technical illustration of some aspects of thetechnology. Not all of the elements illustrated may be present in allembodiments or aspects of the disclosed technology and other embodimentsmay include varying component arrangements, omitted components, and/oradditional equipment, without departing from the scope of the presentdisclosure. FIG. 1 merely provides a simplified illustration of some ofthe basic components used in drilling or servicing subterranean wells,particularly offshore wells, in accordance with the presently disclosedwell control technology.

Generally, the presently disclosed technology involves creating atemporary blockage or impedance of the wellbore blowout fluid flow atthe wellhead by introducing additional fluid into the flow stream atsuch rate as to create an increased backpressure in the wellheadthroughbore that creates sufficient additional pressure drop in the flowcontrol device throughbore that overcomes the flowing wellbore pressureof the blowout fluid flow through the wellhead. In many embodiments, thecontrol fluid is introduced in proximity of an upper or top end of thewellbore, such as into the wellhead, drilling spool, or in a lowerportion of the blowout preventer, or in adjacent equipment such as wellcontrol devices (e.g., blowout preventers, master valves, etc.) thathave an internal arrangement of components exposed to the wellbore thatcreates a relatively restrictive turbulence of control fluid andformation fluid therein. In many aspects, the control fluid introductionrate is sufficiently high so as to create a flowing wellhead pressuredrop within the wellhead primary throughbore and/or related equipmentdue to the fluid mixing and turbulent flow patterns therein, thatexceeds the formation fluid flowing pressure at that point of controlfluid introduction into the wellbore. It may be desired that the backpressure created by the increased fluid flow-rate through the wellcontrol equipment substantially inhibits, reduces, or even halts flow ofthe wellbore blowout fluid from the wellbore. This hydrodynamic wellcontrol operation may be subsequently continued while other operationsto finally and permanently control the well are performed, such aspumping a weighted mud, cement, or another control fluid into the well.In many aspects, the weighted fluid comprises at least one of aseawater, saturated brine, drilling mud, and cement.

Another advantage offered by the present technology is use of readilyavailable and environmentally compatible water or seawater as theintroduced well control fluid. For offshore wells or wells positioned onlakes or inland waterways, this creates essentially a limitless sourceof control fluid, as the control fluid is merely circulated through thesystem. For land-based wells, a water source such as a bank of largetanks may be provided to facilitate circulating water from the tanks,into the primary throughbore, and back to the tanks or to anothercontained facility where the water may could be processed and reused. Asan additional benefit, introducing seawater as the control fluid bringsthe added benefit of fire suppression and thermal reduction in event theeffluent is on fire or has possibility of ignition.

Flow of the wellbore blowout fluid may be sufficiently arrested orhalted (controlled) when sufficient rate of control fluid (e.g., water)is pumped into the well bore through a control fluid aperture(s) in orbelow the well control device as to increase fluid pressure in the wellcontrol device throughbore greater than the flowing pressure of thehydrocarbon flow at the point where the control fluid enters thewellbore. When wellbore blowout fluid is thereby controlled, blowoutflow velocity or rate may be sufficiently halted or have such reducedupward velocity or rate such that a heavier weighted fluid can then beintroduced into the wellbore through a weighted fluid aperture. Theweighted fluid aperture is positioned below the control fluid aperture.The weighted fluid can then fall by gravity through the wellbore blowoutfluid in the wellbore and/or displace the blowout fluid as the weightedfluid moves down the wellbore and begins permanently killing the wellblowout. The well controlling step of introducing the control fluid intothe wellbore may continue while the well killing operation ofintroducing the weighted fluid into the wellbore may be progressed untilthe blowout fluid no longer has the ability to flow at the surface whenthe well controlling operation of introducing the control fluid throughthe control fluid aperture is suspended. Introducing the weighted fluidin parallel with introducing the control fluid can continue until thewellbore is fully hydraulically stabilized and no longer has the abilityto flow uncontrolled. A sufficiently reduced blowout fluid velocity maypermit the weighted fluid to flow into the well bore without beingejected out of the well control device.

The presently disclosed methods and systems also have the advantage ofbeing remotely operable from the rig, vessel or platform experiencingthe blowout, as all operations may be performed from a workboat or othervessel that is safely distant from the blowout. By operating remotelyfrom the drilling rig, the well-control system or operation will not beimpacted by failure of the drilling rig. Further, pumping seawater intothe well control device as the control fluid, not only provides aninfinite source of control fluid, but also brings the advantage ofadding firefighting water into the fuel in the event that thehydrocarbons are ignited after escaping onto the drilling rig. Thissystem could both save the rig, control the well, and if desired providemeans for introducing environmental-cleanup-aiding chemicals directlyinto the blowout effluent stream.

FIG. 1 illustrates an exemplary equipment arrangement for a well controloperation according to the present disclosure, whereby wellbore 50 isexperiencing a well control event and an operation according to thepresent disclosure is employed to intervene and kill the flow ofeffluent from wellbore 50. In the exemplary aspect illustrated in FIG.1, a service vessel 72 is positioned safely apart from or remote offsetfrom the rig 62 or well centerline 11. Exemplary vessel 72 may be loadedwith equipment, pumps, tanks, lines, drilling mud, cement, and/or otheradditives as may be useful in the well control operation. Exemplaryvessel 72 also provides pumps 32, 42 for introducing fluids into thewellbore 50 via pump lines 34 and 44. A wellbore 50 is located within asubterranean formation 60, whereby the wellbore is in fluidcommunication with a reservoir or formation containing sufficientformation fluid pressure to create a well control situation such as ablowout. Top side well control or operation-related equipment ispositioned at several points along the wellbore 50 above the surfacelocation (such as mudline 48 or water surface 74) including at watersurface 74. Wellbore 50 is discharging the wellbore fluid 16 in anuncontrolled flow, from substantially any location downstream (above) ofthe wellhead pressure control devices 20. Wellbore fluid 16 may beescaping or discharged at substantially any location downstream from atleast a portion of the well control surface equipment 20 or from thewellbore throughbore 12, such as near the mudline 48, on a rig orsurface vessel 62 or therebetween. FIG. 1 illustrates the presence of aplurality of well control devices 20, such as a blowout preventer 26(BOP), a lower marine riser package 52 (LMRP), and a marine riser 24.Well control device(s) 20 is(are) engaged with the top end 18 ofwellbore 50. Wellbore 50 includes a wellbore conduit 10 defining awellbore throughbore 12 therein, such as a well casing string(s). Thecollective components comprising the well control device 20 each includea primary throughbore 70 substantially coaxially aligned along awellbore centerline 11 with the wellbore throughbore 12, but notnecessarily having the same primary throughbore internal radialdimensions 28 as the wellbore conduit 10. The primary throughbore 70 isirregular with respect to internal radial dimensions 28 between variouscomponents therein, such as pipe rams 88, wipers, master valves on achristmas tree, plug profiles, and will possess varying internal surfaceroughness and dimensional variations so as to contribute to creation ofturbulent fluid flow therein that under conditions of sufficiently highflow rate may create a substantial pressure drop therein that may impedethe combined flow rate of formation blowout fluid and control fluidthrough the primary throughbore 70, thus aiding in creating enhancebackpressure on the wellbore 50, and reducing or halting effluent 16flow.

In one general aspect, the disclosed technology includes a method ofperforming a well control intervention operation to reduce anuncontrolled flow of wellbore fluids 16 such as a blowout from asubterranean wellbore 50. The term “blowout” is used broadly herein toinclude substantially any loss of well control ability from the surface,including catastrophic events as well as less-notorious occurrences,related to the inability of using surface pressure control equipment 20to contain and control the flow of effluent fluid 16 from within awellbore conduit 10 into the environment outside the well 50.

The disclosed method comprises providing at least one flow controldevice 20, such as a BOP 26, LMRP 52, Christmas tree valve arrangement,and snubbing equipment. The term “BOP” is used broadly herein togenerally refer to the totality of surface or subsea well pressure orfluid controlling equipment present on the wellbore that comprises atleast a portion of the wellbore throughbore 12 and which is typicallyappended to the top end 18 of the wellbore conduit 10 during anoperation of, on, or within the well 50. The main internal well controldevice 20 throughbore 70 within the flow control devices may be referredto broadly herein as the primary throughbore 70. The wellborethroughbore 12 includes the primary throughbore 70. The well controldevice 20 is typically engaged with a top end 18 of the wellbore conduit10 at a surface location of the wellbore conduit, such as at theseafloor mudline 48 (or land surface or platform or vessel surface). Theprimary throughbore 70 is coaxially aligned with the wellborethroughbore 12 and the primary throughbore 70 comprises internaldimensional irregularities such as constrictions and discontinuities,along the primary throughbore conduit 70 inner wall surface. Theseirregularities may be due to varying positions and dimensions related tointernal components such as pipe rams, plug seats, master valves, orother internal features that may create a substantially discontinuous orirregular conduit path along the axial length of the primary conduit 70.

A control fluid aperture 30 is provided in proximity to the fluidcontrol device 20, preferably located either in a lower half of thefluid control device 20 or at a point in the wellbore conduit 10 below(upstream with respect to the direction of blowout fluid flow) the fluidcontrol device 20, such as in a drilling spool, a drilling choke-killcross. The control fluid aperture 30 may include multiple of suchapertures. The control fluid aperture 30 serves as a port(s) tointroduce the control fluid into the wellbore at sufficient rate,volume, and pressure to, in combination with the formation fluid 16 orwholly alone, increase the total fluid flow rate through the primarythroughbore 70 so as to impede or halt flow of formation fluid 16through the wellbore conduit below the control fluid aperture 30. Thecontrol fluid aperture 30 may be provided in the top end 18 of thewellbore conduit 10, meaning substantially anywhere along the wellborethroughbore 12 above (uphole from) the bradenhead flange or mudline,wherein the control fluid aperture is also fluidly connected with thewellbore throughbore, or combinations thereof. The ports may begenerally provided substantially perpendicular to the axis of thethroughbore. In other aspects, the control fluid aperture 30 may beprovided in at least one of (i) the top end of the wellbore conduit,(ii) the flow control device, and (iii) a location intermediate (i) and(ii), the control fluid aperture being fluidly connected with thewellbore throughbore, or combinations thereof. Introduction of thecontrol fluid is introduced through the control fluid aperture 30,whereby the introduced control fluid may fluidly overwhelm the fluidflow through the wellbore throughbore 12 and may thereby providetemporary suspension or sufficient reduction in flow of wellbore blowoutfluid 16 as to render the well at least temporarily controlled orkilled. Thereafter more permanent and conventional killing operationsmay proceed, such as via introduction of a hydrate inducing fluid toprovide hydrostatic control and containment of the wellbore 50.

In addition to the control fluid aperture 30, the disclosed technologyprovides a hydrate inducing fluid aperture 40 for introducing a weightedfluid into the wellbore below the control fluid aperture 30 to providethe hydrostatic control and containment of well effluent 16 from thewellbore 50. In some aspects it may be preferred to locate the hydrateinducing fluid aperture 40 in the wellbore throughbore 12 in proximityto the mudline 48, such as near the top end 18 of the wellbore conduit10, or in a lower portion of the fluid control device 20 that is belowthe control fluid aperture. The term “below” means an upstream locationin the wellbore throughbore with respect to direction of flow ofwellbore blowout fluid 16 flowing through the throughbore 12. In someembodiments, the control fluid aperture may be located within a BOPbody, between BOP rams, or in a drilling spool (choke-kill spool), orcombinations thereof. In some aspects, it may be useful to provide thecontrol fluid aperture 30 in the well control device 20 and providingthe hydrate inducing fluid aperture in another wellbore component below(upstream with respect to the direction of flow of wellbore fluidflowing through the wellbore throughbore) from the well control device20, or in both locations to have sufficient control fluid introductioncapacity.

Introducing a control fluid through the control fluid aperture 30 intothe wellbore throughbore 12 while wellbore blowout fluid 16 flows fromthe subterranean formation 60 through the wellbore throughbore 12 may insome instances provide sufficient backpressure to both temporarilycontrol and permanently control the well. In the case of a relativelylow-pressure wellbore (e.g., one having a BHP gradient of less than aseawater, kill mud, or freshwater gradient) the control fluid alone mayperform to both temporarily control the well and with continued pumpingalso serve as the weighted fluid to fill the wellbore with control fluidand permanently kill the well. It may be advantageous to introduce atleast a portion or as much as possible of the control fluid into theprimary throughbore 20 as far upstream (low) as possible, such as in thelower half of the BOP 26, such as below BOP mid-line 15, withouthydraulically interfering with introduction of the hydrate inducingfluid into the hydrate inducing fluid aperture 40.

The presently disclosed technology also includes an apparatus and systemfor performing a wellbore intervention operation to reduce anuncontrolled flow rate of wellbore fluids from a subterranean wellbore.In one embodiment, as illustrated in exemplary FIG. 1, the apparatus orsystem may comprise a flow control device 20 mechanically and fluidlyengaged (directly or including other components engaged therewith) witha top end of a wellbore conduit (generally the wellhead at the surfaceor mudline, but in proximity thereto such as in a conductor casing orother conduit in proximity to the mudline or surface) that includes awellbore throughbore 12 at a surface location 48 of the wellboreconduit, the flow control device 20 including a primary throughbore 70that is included within the wellbore throughbore 12, the primarythroughbore 70 coaxially aligned with the wellbore throughbore 12 andthe primary throughbore 70 comprising internal dimensionalirregularities. “Internal dimensional irregularities” and like termsrefers to the primary throughbore 70 having a non-uniform effectiveinternal conduit-forming surfaces or internal cross-sectional area orinternal diameter dimensions, along the axial length of the primarythroughbore 70 as compared with the substantially uniform internaldiameter of the wellbore conduit 10. The internal dimensions of theprimary throughbore may be less than, greater than, or in some instancessubstantially the same as the internal diameter of the wellbore conduit10. “Internal dimensional irregularities” variations include theinternal component positional and size variations within the variousapparatus, valves, BOP's, etc., that comprise the primary throughbore 70downstream from (above) the hydrate inducing fluid introductionaperture. Such varying internal diameter variations provide internalfluid flow-disrupting edges and shape inconsistencies along the axiallength of the primary throughbore 70 that collectively may facilitatesubstantial turbulent flow and enhanced rate restriction, resulting inincreased hydraulic pressure drop along the primary throughbore 70.

The control fluid is introduced into the wellbore throughbore insufficient rate to create a substantial hydrodynamic pressure dropwithin the primary throughbore 70, such as a pressure drop of at least10%, or at least 25%, or at least 50%, or at least 75%, or at least 100%from the previously estimated or determined flowing hydraulic pressureof the wellbore blowout fluid within the primary throughbore 70 beforeintroduction of the control fluid therein. It is anticipated that thecontrol fluid may commonly need to be introduced into the primarythroughbore 12 at a control fluid introduction rate that is at least25%, or at least 50%, or at least 100%, or at least 200% of thepreviously estimated or determined wellbore blowout fluid 16 flow ratefrom the wellbore throughbore 12 prior to introducing the control fluidinto the wellbore throughbore 12. In another aspect, it may be desiredthat when substantially only, or at least a majority by volume, or atleast 25% by volume of the total fluid flowing (formation effluent pluscontrol fluid) through the downstream, outlet end of the primarythroughbore 70 is control fluid, then a weighted fluid such as weightedmud, cement, weighted kill fluid, or heavy brine may be introducedpreferably through the weighted fluid aperture 40 and into the wellborethroughbore 12 while pumping the control fluid through the control fluidaperture 30.

There may be applications where it is desired to begin pumping weightedfluid through the control fluid aperture, either solely or incombination with introducing weighted fluid into the weighted fluidaperture. In such instances such instances, the weighted fluid may besubstantially the same fluid as the control fluid, or another weightedfluid.

When the well is killed (exhibiting either reduced flow rate or haltedflow rate of formation fluids from the reservoir or formation 60) due tointroduction of control fluid into the primary throughbore 70, the wellwill still be flowing the control fluid from the primary throughbore 70exit. In many instances it is preferred that the well is killed withrespect to flow of formation effluent through the primary throughbore,and substantially all of the fluid discharging from the primarythroughbore 70 is control fluid. Thereby, wellbore blowout fluid 16 iseffectively replaced with control fluid such as seawater 80.

Introducing “neat” control fluid (without additives) into the wellborethroughbore 12 may or may not fully contain or halt formation fluid flowfrom the well 50 as desired. Some aspects of the disclosed technologymay include tailoring the control fluid. In other aspects, it may bedesirable to provide additives 86 through additive lines 84, 85 to thecontrol fluid (or the weighted fluid) by adding fluid-enhancingcomponents therein, such as salts, alcohols, surfactants, biocides, andpolymers. In some embodiments, the control fluid may comprise at leastone of carbon dioxide, nitrogen, air, methanol, another alcohol, NaCl,KCl, MgCl, another salt, and combinations thereof.

In some operations it may be desirable to introduce fluid streamscomprising or consisting of polymerizable formulations (broadly referredto herein as polymers, including actual polymers or other chemicallyactivated or reactive mass-forming combinations of components),including polymerizable formulations that activate or polymerize withinthe primary throughbore 70 to create a polymer accumulation within theprimary throughbore 70. Such polymerizable formulations may be amulti-component chemical or polymer formulations wherein each of thereactant components are separately introduced into the primarythroughbore 70 for mixing and (quickly) reacting or (quickly)polymerizing therein. Such polymers may also include chemical or polymerformulations that are water or hydrocarbon activated compositions. Theactivated polymers may accumulate or otherwise volumetrically build upwithin the primary throughbore, creating a flowpath restriction,constriction, or full blockage of the fluid flow rate through theprimary throughbore 70. Fibrous and/or granular solids such as nylons,kevlars, durable materials, or fiberglass materials may also beconcurrently introduced for enhancing the toughness or shear strength ofthe polymer accumulation within the primary throughbore 70.

In some applications, it may be useful to introduce the control fluidinto the wellbore throughbore 12 at a control fluid introduction ratethat indirectly provides other associated desired effects, such ascreating hydrates within the wellbore throughbore 12 such as by theintroduction of carbon dioxide into the control fluid. Creation ofhydrates within the primary throughbore 70 may assist with increasingthe pressure drop through the primary throughbore as hydrate formationprogresses, by reducing the flow cross-sectional area and internalsurface roughness within the primary throughbore. Conversely, at someambient temperatures or conditions it may be desirable to inhibithydrate formation within the control fluid apertures 30 or lines 34 inorder to sustain maximum flow rate therein and it may be useful tointroduce a hydrate inhibition component such as an alcohol into thecontrol fluid.

In some applications, it may be desirable to introduce control fluidinto the wellbore throughbore 12 at a control fluid introduction ratesufficient to reduce the wellbore fluid flow rate by determined amount,such as achieving a reduction of at least 10%, or 25%, or 50%, 75%, or90%, or at least 100%, (by volume) with respect to the wellbore blowoutfluid 16 flow rate through the wellbore throughbore 12 or primarythroughbore 70, prior to introduction of the control fluid into theprimary throughbore 70.

The disclosed apparatus or system includes a control fluid aperture 30in at least one of (i) the top end of the wellbore conduit, (ii) theflow control device, and (iii) a location intermediate (i) and (ii), thecontrol fluid aperture being fluidly connected with the wellborethroughbore. The control fluid aperture 30 facilitates introducing (suchas by pumping or by gravitational flow) a control fluid into thewellbore throughbore 12 while a wellbore fluid flows from thesubterranean formation 60 through the wellbore throughbore 12 at awellbore fluid flow rate, whereby the control fluid is introduced at acontrol fluid introduction rate of at least 25% (by volume) of theestimated or determined wellbore fluid flow rate was from the wellborethroughbore prior to introducing the control fluid into the wellborethroughbore.

A hydrate inducing fluid aperture 40 is also provided for introducinghydrate inducing fluid into the wellbore throughbore 12. The aperture 40is positioned at an upstream location in the wellbore throughbore withrespect to the control fluid aperture and with respect to direction offlow of wellbore fluid flowing through the wellbore throughbore (e.g.,the hydrate inducing fluid aperture 40 is generally positioned below thecontrol fluid aperture 30 and in some embodiments the hydrate inducingfluid aperture 40 may be positioned below the fluid control device 20 ornear a lower end of the fluid control device 20. The hydrate inducingfluid aperture 40 is sized and/or provided by sufficient number ofapertures 40 to be capable to introduce a hydrate inducing fluid intothe wellbore throughbore 12 while the control fluid is introduced intothe wellbore primary throughbore 70 through the control fluid aperture30, from a control fluid conduit line 34 and a control fluid pump 32.

“Flow control device” 20 is a broad term intended to refer generally tothe any of the pressure and/or flow control regulating devicesassociated with the top end 18 of the well 50, including equipment neara mudline 48, an earthen surface, or other water surface, that may beused in conjunction with controlling wellbore pressure and/or fluid flowduring a well operation. The collection of such devices may generallydefine the “primary throughbore” portion of the wellbore throughbore 12.Exemplary well operations using a flow control device includesubstantially any operation that may encounter wellbore pressure orflow, such as drilling, workover, well servicing, production,abandonment operation, and/or a well capping operation, and exemplaryequipment includes at least one of a BOP 28, LMRP 52, at least a portionof a riser assembly, a production tree, choke/kill spool, andcombinations thereof.

The present apparatus or system also includes a control fluid conduit 34and a control fluid pump 32 in fluid communication with the controlfluid aperture 30. In some aspects, suction for the pump may be drawnfrom a suction line 82 in fluid connection with the adjacent watersource 80, such as the ocean, a freshwater source, large water tanks,etc. Using seawater or other readily available fluid as the controlfluid whereby the blowout effluent is discharging into the oceanprovides a substantially limitless source of environmentally compatiblecontrol fluid. Thereby, the limitations on control fluid introductionrate and duration are merely mechanical issues that may be addressed orenhanced separately (e.g., control fluid aperture size and number ofapertures available, pressure ratings, pump capacity, etc.). Multipleapertures fluid connected with the wellbore throughbore 12 may beutilized as the control fluid apertures 30. The multiple apertures maybe located substantially anywhere within and/or upstream of (below) theprimary throughbore 70. It is preferred that the most downstream(highest) hydrate inducing fluid aperture 40 is upstream of (below) allof the control fluid apertures 30, with preferably at least 3 but morepreferably at least 5 and even more preferably at least 7 wellboreconduit effective internal diameters of the wellbore blowout fluid 16flow stream separating the most upstream (lowest) control fluid aperture30 from the most downstream (highest) hydrate inducing fluid aperture40. Stated differently, the hydrate inducing fluid aperture 40 isupstream of (below) the nearest control fluid aperture 30, by at least3, 5, or 7 internal diameters of the wellbore conduit throughbore 12.

Thereby, the hydrate inducing fluid does not encounter the majority ofthe mixing and turbulent hydraulic energy imposed into the wellborethroughbore 12. It may also be preferred in some aspects that thehydrate inducing fluid aperture is positioned upstream (below) of theprimary throughbore 70.

It may be desirable in some aspects that control fluid pump 32 andcontrol fluid conduit 34 are capable of pumping control fluid throughthe control fluid aperture(s) 30 and into the wellbore throughbore 12 ata control fluid introduction rate of at least 25%, or at least 50%, orat least 100%, or at least 200% (by volume) of the wellbore fluid flowrate through the wellbore throughbore 12 that was estimated ordetermined prior to introduction of the control fluid into the wellborethroughbore 12. The larger the total fluid flow rate through the primarythroughbore 70, the greater the hydraulic pressure drop created thereinby the combined fluid streams, and the larger the volumetric fraction ofcontrol fluid introduced therein that comprises the total fluid stream,the lower the volumetric fraction of wellbore effluent 16 escaping intothe environment from the wellbore 50. It may be desirable in otheraspects to introduce sufficient control fluid into the wellbore suchthat the fractional rate of wellbore effluent from the reservoir issubstantially nothing or incidental. In another aspect, it may bedesirable that an estimated or determined at least 25% by volume, or atleast 50% or at least 75% or at least 100% by volume of the total fluid(control fluid plus formation effluent wellbore blowout fluid) flowingthrough the primary throughbore during introduction of the control fluidinto the primary throughbore is control fluid. The hydrate inducingfluid may be introduced through the hydrate inducing fluid aperture andinto the wellbore throughbore while pumping the control fluid throughthe control fluid aperture.

The hydrate inducing fluid aperture 40 is positioned preferably belowthe control fluid aperture 30 and the hydrate inducing fluid aperture(s)is dimensioned to provide flow rate capacity to introduce hydrateinducing fluid into the wellbore throughbore at a rate whereby theweighted fluid falls through the stagnant or reduced velocity wellborefluid effluent flow rate through the wellbore throughbore 12. In someapplications such as when it may be desirable introduce a high rate ofhydrate inducing fluid into the wellhead 18, it may be desirable toswitch from introducing the control fluid into the control fluidaperture to introducing hydrate inducing fluid into the control fluidaperture, such as while also introducing hydrate inducing fluid into thehydrate inducing fluid aperture.

As used herein, the term “and/or” placed between a first entity and asecond entity means one of (1) the first entity, (2) the second entity,and (3) the first entity and the second entity. Multiple entities listedwith “and/or” should be construed in the same manner, i.e., “one ormore” of the entities so conjoined. Other entities may optionally bepresent other than the entities specifically identified by the “and/or”clause, whether related or unrelated to those entities specificallyidentified. Thus, as a non-limiting example, a reference to “A and/orB,” when used in conjunction with open-ended language such as“comprising” may refer, in one embodiment, to A only (optionallyincluding entities other than B); in another embodiment, to B only(optionally including entities other than A); in yet another embodiment,to both A and B (optionally including other entities). These entitiesmay refer to elements, actions, structures, steps, operations, values,and the like.

As used herein, the phrase “at least one,” in reference to a list of oneor more entities should be understood to mean at least one entityselected from any one or more of the entity in the list of entities, butnot necessarily including at least one of each and every entityspecifically listed within the list of entities and not excluding anycombinations of entities in the list of entities. This definition alsoallows that entities may optionally be present other than the entitiesspecifically identified within the list of entities to which the phrase“at least one” refers, whether related or unrelated to those entitiesspecifically identified. Thus, as a non-limiting example, “at least oneof A and B” (or, equivalently, “at least one of A or B,” or,equivalently “at least one of A and/or B”) may refer, in one embodiment,to at least one, optionally including more than one, A, with no Bpresent (and optionally including entities other than B); in anotherembodiment, to at least one, optionally including more than one, B, withno A present (and optionally including entities other than A); in yetanother embodiment, to at least one, optionally including more than one,A, and at least one, optionally including more than one, B (andoptionally including other entities). In other words, the phrases “atleast one,” “one or more,” and “and/or” are open-ended expressions thatare both conjunctive and disjunctive in operation. For example, each ofthe expressions “at least one of A, B and C,” “at least one of A, B, orC,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B,and/or C” may mean A alone, B alone, C alone, A and B together, A and Ctogether, B and C together, A, B and C together, and optionally any ofthe above in combination with at least one other entity.

The phrase “etc.” is not limiting and is used herein merely forconvenience to illustrate to the reader that the listed examples are notexhaustive and other members not listed may be included. However,absence of the phrase “etc.” in a list of items or components does notmean that the provided list is exhaustive, such that the provided liststill may include other members therein.

In the event that any patents, patent applications, or other referencesare incorporated by reference herein and (1) define a term in a mannerthat is inconsistent with and/or (2) are otherwise inconsistent with,either the non-incorporated portion of the present disclosure or any ofthe other incorporated references, the non-incorporated portion of thepresent disclosure shall control, and the term or incorporateddisclosure therein shall only control with respect to the reference inwhich the term is defined and/or the incorporated disclosure was presentoriginally.

As used herein the terms “adapted” and “configured” mean that theelement, component, or other subject matter is designed and/or intendedto perform a given function. Thus, the use of the terms “adapted” and“configured” should not be construed to mean that a given element,component, or other subject matter is simply “capable of” performing agiven function but that the element, component, and/or other subjectmatter is specifically selected, created, implemented, utilized,programmed, and/or designed for the purpose of performing the function.It is also within the scope of the present disclosure that elements,components, and/or other recited subject matter that is recited as beingadapted to perform a particular function may additionally oralternatively be described as being configured to perform that function,and vice versa.

As used herein, the phrase, “for example,” the phrase, “as an example,”and/or simply the term “example,” when used with reference to one ormore components, features, details, structures, embodiments, and/ormethods according to the present disclosure, are intended to convey thatthe described component, feature, detail, structure, embodiment, and/ormethod is an illustrative, non-exclusive example of components,features, details, structures, embodiments, and/or methods according tothe present disclosure. Thus, the described component, feature, detail,structure, embodiment, and/or method is not intended to be limiting,required, or exclusive/exhaustive; and other components, features,details, structures, embodiments, and/or methods, including structurallyand/or functionally similar and/or equivalent components, features,details, structures, embodiments, and/or methods, are also within thescope of the present disclosure.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to the oil andgas industries.

It is believed that the disclosure set forth above encompasses multipledistinct inventions with independent utility. While each of theseinventions has been disclosed in its preferred form, the specificembodiments thereof as disclosed and illustrated herein are not to beconsidered in a limiting sense as numerous variations are possible. Thesubject matter of the inventions includes all novel and non-obviouscombinations and subcombinations of the various elements, features,functions and/or properties disclosed herein. Similarly, where theclaims recite “a” or “a first” element or the equivalent thereof, suchclaims should be understood to include incorporation of one or more suchelements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certaincombinations and subcombinations that are directed to one of thedisclosed inventions and are novel and non-obvious. Inventions embodiedin other combinations and subcombinations of features, functions,elements and/or properties may be claimed through amendment of thepresent claims or presentation of new claims in this or a relatedapplication. Such amended or new claims, whether they are directed to adifferent invention or directed to the same invention, whetherdifferent, broader, narrower, or equal in scope to the original claims,are also regarded as included within the subject matter of theinventions of the present disclosure.

What is claimed is:
 1. A method of performing a wellbore interventionoperation to reduce an uncontrolled flow of wellbore fluids from asubterranean wellbore, the method comprising: providing a flow controldevice, the flow control device engaged proximate a top end of awellbore conduit that includes a wellbore throughbore, the flow controldevice including a primary throughbore coaxially aligned with andincluded within the wellbore throughbore; providing a control fluidaperture proximate the top end of the wellbore conduit, the controlfluid aperture being fluidly connected with the primary throughbore;providing a hydrate inducing fluid aperture in the wellbore throughboreat an upstream location in the wellbore throughbore with respect to thecontrol fluid aperture and with respect to the direction of wellboreblowout fluid flow through the wellbore throughbore; introducing acontrol fluid through the control fluid aperture and into the wellborethroughbore while the wellbore blowout fluid flows at an uncontrolledrate from the subterranean formation and through the wellborethroughbore at a wellbore blowout fluid flow rate, whereby the controlfluid is introduced into the wellbore throughbore at a control fluidintroduction rate that is at least 25% of the wellbore blowout fluidflow rate from the wellbore throughbore prior to introducing the controlfluid into the wellbore throughbore; and introducing a hydrate inducingfluid through the hydrate inducing fluid aperture and into the wellborethroughbore while simultaneously introducing the control fluid throughthe control fluid aperture at the control fluid introduction rate toinduce the formation and deposition of hydrates within the wellbore andaffect the flow rate of the wellbore blowout fluid flow rate from thewellbore throughbore.
 2. The method of claim 1, wherein the flow controldevice comprises at least one of a drilling spool, a blowout preventer,a lower marine riser package, and a riser assembly.
 3. The method ofclaim 1, comprising providing the control fluid aperture in or upstreamof the well control device and providing the hydrate inducing fluidaperture in another wellbore component upstream from the well controldevice with respect to the direction of flow of wellbore blowout fluidflowing through the wellbore throughbore.
 4. The method of claim 1,further comprising introducing the control fluid into the primarythroughbore at a control fluid introduction rate of at least 50% of thewellbore blowout fluid flow rate prior to introduction of the controlfluid into the wellbore throughbore.
 5. The method of claim 1, furthercomprising introducing the control fluid into the primary throughbore ata control fluid introduction rate of at least 100% of the wellboreblowout fluid flow rate prior to introduction of the control fluid intothe wellbore throughbore.
 6. The method of claim 1, further comprisingintroducing the control fluid into the primary throughbore at a controlfluid introduction rate of at least 200% of the wellbore blowout fluidflow rate prior to introduction of the control fluid into the wellborethroughbore.
 7. The method of claim 1, further comprising using seawaterfor control fluid.
 8. The method of claim 1, further comprisingintroducing the hydrate inducing fluid through the hydrate inducingfluid aperture and into the wellbore throughbore when an estimated ordetermined at least 25% by volume of total fluid flowing through theprimary throughbore during introduction of the control fluid into theprimary throughbore is control fluid.
 9. The method of claim 1, furthercomprising creating hydrate formation within the wellbore throughborewith the control fluid.
 10. The method of claim 9, wherein the hydrateinducing fluid comprises at least one of an alkane and water furthercomprising introducing carbon dioxide into the control fluid to createhydrates within the wellbore throughbore.
 11. The method of claim 1,further comprising introducing control fluid into the wellborethroughbore at a control fluid introduction rate sufficient to reducethe wellbore blowout fluid flow rate by 25% with respect to the wellboreblowout fluid flow rate through the wellbore throughbore prior tointroduction of the control fluid into the wellbore throughbore.
 12. Themethod of claim 1, further comprising introducing control fluid into thewellbore throughbore at a control fluid introduction rate sufficient toreduce the wellbore blowout fluid flow rate by at least 50% with respectto the wellbore blowout fluid flow rate through the wellbore throughboreprior to introduction of the control fluid into the wellborethroughbore.
 13. The method of claim 1, further comprising introducingcontrol fluid into the wellbore throughbore at a control fluidintroduction rate sufficient to reduce the wellbore blowout fluid flowrate by at least 75% with respect to the wellbore blowout fluid flowrate through the wellbore throughbore prior to introduction of thecontrol fluid into the wellbore throughbore.
 14. The method of claim 1,further comprising introducing control fluid into the wellborethroughbore at a control fluid introduction rate sufficient to reducethe wellbore blowout fluid flow rate by at least 90% with respect to thewellbore blowout fluid flow rate through the wellbore throughbore priorto introduction of the control fluid into the wellbore throughbore. 15.The method of claim 1, further comprising providing the control fluidaperture in at least one of (i) the flow control device, and (ii) alocation intermediate the flow control device and the wellbore conduit.16. The method of claim 1, further comprising thereafter introducinghydrate inducing fluid through the control fluid aperture.
 17. Anapparatus for performing a wellbore intervention operation to reduce anuncontrolled flow rate of wellbore fluids from a subterranean wellbore,the apparatus comprising: a flow control device, the flow control deviceengaged proximate a top end of a wellbore conduit that includes awellbore throughbore at a surface location of the wellbore conduit, theflow control device including a primary throughbore that includes thewellbore throughbore, the primary throughbore coaxially aligned with thewellbore throughbore; a control fluid aperture proximate the top end ofthe wellbore conduit, the control fluid aperture being fluidly connectedwith the wellbore throughbore, the control fluid aperture positioned tointroduce a control fluid into the primary throughbore concurrent withwellbore blowout fluid flowing from the subterranean formation at anuncontrolled rate through the wellbore throughbore at a wellbore fluidflow rate; a hydrate inducing fluid aperture in the wellbore throughborepositioned at an upstream location in the wellbore throughbore withrespect to the control fluid aperture and with respect to direction offlow of wellbore blowout fluid flowing through the wellbore throughbore,the hydrate inducing fluid aperture capable to introduce a hydrateinducing fluid into the wellbore throughbore while the control fluid isintroduced into the wellbore throughbore through the control fluidaperture at the control fluid introduction rate.
 18. The apparatus ofclaim 17, wherein the flow control apparatus comprises at least one of ablowout preventer, lower marine riser package, at least a portion of ariser assembly, production tree, drilling spool, and combinationsthereof.
 19. The apparatus of claim 17, wherein the control fluidaperture is fluidly connected with a control fluid conduit and a controlfluid pump.
 20. The apparatus of claim 17, further comprising sizing thecontrol fluid aperture to introduce a control fluid into the wellborethroughbore at a control fluid introduction rate of at least 25% of anestimated or determined wellbore blowout fluid flow rate through thewellbore throughbore that was estimated or determined prior tointroduction of the control fluid into the wellbore throughbore.
 21. Theapparatus of claim 19, wherein the control fluid pump and control fluidconduit are capable of introducing control fluid through the controlfluid aperture and into the wellbore throughbore at a control fluidintroduction rate of at least 50% of the wellbore blowout fluid flowrate through the wellbore throughbore prior to introduction of thecontrol fluid into the wellbore throughbore.
 22. The apparatus of claim19, wherein the control fluid pump and control fluid conduit are capableof introducing control fluid through the control fluid aperture and intothe wellbore throughbore at a control fluid introduction rate of atleast 100% of the wellbore blowout fluid flow rate through the wellborethroughbore prior to introduction of the control fluid into the wellborethroughbore.
 23. The apparatus of claim 19, wherein the control fluidpump and control fluid conduit are capable of introducing control fluidthrough the control fluid aperture and into the wellbore throughbore ata control fluid introduction rate of at least 200% of the wellboreblowout fluid flow rate through the wellbore throughbore prior tointroduction of the control fluid into the wellbore throughbore.
 24. Theapparatus of claim 17, wherein the weighted fluid aperture isdimensioned to introduce weighted fluid into the wellbore throughbore ata rate whereby the weighted fluid falls through the wellbore fluid. 25.The apparatus of claim 17, wherein the hydrate inducing fluid apertureis upstream of the nearest control fluid aperture, by at least threeinternal diameters of the wellbore conduit throughbore.
 26. Theapparatus of claim 17, wherein the hydrate inducing fluid aperture isupstream of the nearest control fluid aperture, by at least fiveinternal diameters of the wellbore conduit throughbore.
 27. Theapparatus of claim 17, wherein the control fluid comprises at least oneof seawater, freshwater, saturated brine, and a drilling mud.
 28. Theapparatus of claim 27, wherein the control fluid further comprises atleast one of carbon dioxide, nitrogen, air and combinations thereof. 29.The apparatus of claim 17, wherein the hydrate inducing fluid comprisesat least one of a seawater, saturated brine, drilling mud, and cement.30. The apparatus of claim 17, wherein the control fluid aperture islocated in at least one of a blowout preventer and a drilling spool. 31.The apparatus of claim 17, further comprising a vessel remotely locatedwith respect to wellbore centerline, the vessel having at least one ofthe control fluid pump and the hydrate inducing fluid pump.
 32. Theapparatus of claim 17, wherein the hydrate inducing fluid aperture inthe wellbore throughbore is provided at an upstream location in thewellbore throughbore with respect to the control fluid aperture and withrespect to the direction wellbore blowout fluid flow through thewellbore throughbore.